Q&A

(2019) Question 26A: What is important for feedstock selection for a hydroprocessing unit regarding incompatibility? What related concerns are there in a heavy gasoil resid unit? What feedstock quality parameters are used to predict and /or prevent these issues?

GRANT YOKOMIZO and JOHN PETRI (Honeywell UOP)
A hydroprocessing unit can be designed to handle all potential feedstocks when there is a detailed understanding of the feedstocks’ characteristics. Specifically feedstock selection regarding incompatibility limits needs to be considered as a broad and

(2019) Question 26B: What concerns should be addressed before applying dewaxing catalyst in diesel service? What changes can be expected in unit operation with dewaxing?

AMIT KELKAR (Shell Catalysts & Technologies)
Dewaxing involves isomerization or / and cracking of linear paraffinic molecules to improve cold flow properties such as cloud and pour point. It may be required in winter season in cold climates to maintain flow properties of diesel. Economic benefits of

(2019) Question 27: What do you do to predict Silicon breakthrough in a naphtha hydrotreater? What are the consequences to the downstream units if breakthrough occurs?

JOE RYDBERG (CITGO)
CITGO refineries basically operate in the full coking mode which means that on our usual crude blends we do no net VTB for outside sales nor we are a player in the Bunker fuels supply market. Having said that, we have to be watchful of the demand shift that will follow with the

(2013) Question 29: What are the industry practices to take samples around high-pressure equipment which contain light hydrocarbon and H2S? How do you ensure the samples are handled safely and representative of sample stream?

Our Corpus Christi and Pine Bend refineries had standardized on Texas Sampling Incorporated samplers. They provide a variety of closed loop captured sample systems. We have a Sampler Selection Procedure Flowchart that helps us walk through ‘yes’ or ‘no’ decisions considering high RVP (Reid vapor pressure) material, high-pressure material, high temperature material, high H2S (hydrogen sulfide) options, and plugging potential.

(2013) Question 30: What are your design practices for reactor skin thermocouple requirements in a hydrotreater and a hydrocracker for startups and safe operation?

Our minimal requirement for a hydrotreater is three skin thermocouples at the top and bottom heads of the reactors and a full skin thermocouple at the bottom shell of the reactor just about at the tangent line. The option now is a full skin thermocouple at the top of the shell and the middle of the shell.

(2013) Question 31: What is the threshold concentration of arsenic and phosphorus requiring a dedicated trap system? How are the arsenic and phosphorus trap systems specified,and what are the controlling mechanisms?

Arsenic is a big concern because it is a permanent poison that causes fairly significant activity. We generally see around a 60° Floss per weight percent pickup; so, you will want to pay attention to it. As a side note, it is also common in most fractions of hydrotreating: so anything from naphtha to heavy gas oil.

(2013) Question 32: What is a typical range of HDM (hydrodemetallization; metals removal) in a gas oil hydrotreater? Can HDM decline rapidly when metals in the feed become excessive relative to catalyst system design? Is there a point when metals in the feed are so high that they “overwhelm” the demet (demetallization) and main bed catalyst, resulting in lower percent of HDM?

Nickel and vanadium contamination generally come in heavy gas oils and resid hydrotreating. It is obviously not very common in diesels and light feeds. We see that it is about a 5°F to 9°F loss per weight percent combined pickup. The reason you will want to pay attention to these metals is because of their ability to actually diffuse onto the catalyst, so you will need a space to deposit them.

(2013) Question 33: What is the philosophy or criteria for optimizing catalyst bed grading material to prevent high reactor pressure drop from feed containing significant amounts of Fe (iron)?

Certainly, identifying the sources of the iron coming in – whether organic, iron oxides, iron sulfides, or just scale from tanks – is very critical to understanding your best strategy for mitigating pressure drop. Ultimately, when you form iron sulfide, it creates deposits on the bed and coke deposition, and certainly leads to reduced catalyst life.

(2013) Question 34: When processing cracked naphtha, what is done to ensure that polymerization of the diolefins/olefins will not result in pressure drop problems in a reactor or upstream equipment?

Again, we are trying to prevent the polymerization of the olefin/diolefin. The primary concern is trying to prevent contact with oxygen because that will ultimately lead to gum formation. So, the preference would be, if possible, to feed this hot to all the downstream units and avoid intermediate storage.

(2013) Question 35: When processing tight oil crudes, are lower bed pressure drop problems in VGO/resid hydrotreater reactors a concern? If so, what mechanisms explain this issue?

The highly paraffinic nature of the tight crudes and the destabilization of asphaltene molecules can cause precipitation and agglomeration. One of our customers with a gas oil mild hydrocracker switched feedstock to increase amounts of black wax crude. This was a five-reactor system.

Find the answer to your technical question in AFPM's extensive Q&A database.

Q&A